Downhole centrifugal drilling fluid separator

ABSTRACT

In one aspect of the invention, a downhole centrifugal drilling fluid separator has a bore within a tubular body comprising a central axis. The bore is formed to receive drilling fluid comprising particulate matter. At least one fin rigidly fixed within the bore and at least one port formed in a wall of the tubular body. As the drilling fluid flows through the tubular body the at least one fin creates a rotary motion within the drilling fluid forcing a portion of the particulate matter away from the central axis and through the at least one port in the tubular body.

CROSS REFERENCE TO RELATED APPLICATIONS

This application is a continuation of U.S. patent application Ser. No.12/910,924, which was filed on Oct. 25, 2010.

BACKGROUND OF THE INVENTION

The present invention relates to downhole drilling assemblies,specifically downhole drilling assemblies for use in oil, gas,geothermal, and horizontal drilling. Drilling fluid may comprise any ofa number of liquid and gaseous fluids and mixtures of fluids and solidsused in operations to drill boreholes into the earth. In theseoperations, drilling fluid may remove cuttings from the well, controlformation pressures, seal permeable formations, maintain wellborestability, and minimize formation damage.

Controlling the drilling fluid's weight may contribute to maintainingthe stability of the wellbore. As formation pressures increase, thedrilling fluid's weight may also be increased to maintain the wellbore'sintegrity. However, in some situations, where the drilling fluid'sweight exerts a pressure against the formation that is significantlylower than the formation pressure, the formation's pressure may causethe well bore to collapse. The prior art discloses applications wheredrilling fluid weight has been altered to contribute to drillingapplications.

U.S. Patent Publication No. 2005/0284641 to Watkins et al., which isherein incorporated by reference for all that it contains, discloses avariable density fluid for wellbore operations and a method of drillinga wellbore using a variable density fluid where the density of the fluidchanges by design as a function of external parameters which vary alongthe depth or length of the well. The variable density of the fluid isbeneficial for controlling sub-surface pressures within desirable porepressure and fracture gradient envelopes. The variability of fluiddensity permits construction and operation of a wellbore with muchlonger hole sections than when using conventional single gradientfluids.

U.S. Pat. No. 4,103,749 to Erickson et al., which is herein incorporatedby reference for all that it contains, discloses a centrifugal cleanerpowered by a turbine. Both the centrifugal cleaner and turbine aredownhole in a housing at the end of a drill string. A branch of adrilling mud stream is cleaned of solid matter by the centrifugalcleaner. A branch of the clean fluid drives the turbine of thecentrifugal cleaner. A second branch of the clean fluid does useful workat the downhole location, such as erosive drilling of bore hole rock.Turbine exhaust, cleaner exhaust and drilling mud combine and flow intothe rock erosion zone to clear it of chips formed by the drilling. Fluidfrom this zone passes up the annulus between the bore hole and the drillstring.

BRIEF SUMMARY OF THE INVENTION

In one aspect of the present invention, a downhole centrifugal drillingfluid separator may comprise a bore within a tubular body. The tubularbody may comprise a central axis and may be formed to receive drillingfluid comprising particulate matter. At least one fin may be rigidlyfixed within the bore and at least one port formed in a wall of thetubular body. As drilling fluid flows through the tubular body, the atleast one fin may create a rotary motion within the drilling fluidforcing a denser portion of the drilling fluid, which comprises moreconcentrated particulate matter, away from the central axis and throughthe at least one port.

The at least one fin may comprise a rounded leading edge followed by asharp trailing edge to decrease drag. In one embodiment, a plurality offins may be spaced around a circumference of the bore to furtherfacilitate a rotary motion within the drilling fluid. The plurality offins spaced around the circumference may share substantially the sameangle of attack. The plurality of fins may also be attached to both thetubular body and to a hub disposed at the central axis of the tubularbody. The fins may also be spaced axially along the bore with increasingangles of attack in the direction of the drilling fluid flow.

In another embodiment of the present invention, a plurality of ports maybe spaced around the circumference of the bore. The plurality of portsmay direct fluid comprising particulate matter into the annulus of thewellbore. The bore may comprise a tapered diameter adjacent to theplurality of ports. The tapered diameter may facilitate the flow of theportion of denser drilling fluid through the plurality of ports. Thetapered diameter may also permit a lighter portion of drilling fluidcomprising a reduced concentration of particulate matter to continueflowing through the bore.

The lighter portion of drilling fluid may be used for power generation,drilling, steering, or for use with other downhole tools. The lighterportion may be directed to the drill bit nozzles, where the fluid exits.As the lighter portion travels up the annulus of the wellbore, it maycoalesce with the denser portion of drilling fluid, and a mixture of thedenser and lighter portions of fluid may travel up the remainder of theannulus together.

In another embodiment of the present invention, a method for separatingmixed drilling mud downhole may include the following steps: providing abore within a tubular body comprising a central axis, a drill bit withat least one nozzle, at least one fin, and at least one port; pumping amixed drilling mud through the bore; forcing a denser portion of themixed drilling mud away from the central axis of the bore through thecentrifugal force created by the at least one fin; directing the denserportion of drilling mud through the at least one port and a lighterportion of drilling mud through the length of the bore to the drill bitand into the borehole to facilitate drilling; merging the denser andlighter portions of drilling mud in the annulus of the borehole andcirculating the mixed drilling mud to the surface of the borehole; anddirecting the lighter portion of drilling mud through the drill bit.

In another aspect of the present invention, a downhole drilling fluidseparator has a bore within a tubular body with a central axis andformed to receive drilling fluid. At least one fin is disposed withinthe bore, and at least one downhole tool is disposed within a primarypathway downstream of the at least one fin. An alternate pathway is alsodownstream of the least one fin and by passes the at least one tool. Theprimary and alternate pathways converge downstream of the at least onetool. As drilling fluid flows through the tubular body the at least onefin creates a rotary motion within the drilling fluid forcing a denserportion of the fluid into the alternate pathway while a lighter portionof the fluid is routed into the primary pathway.

In yet another aspect of the present invention, a downhole drillingfluid separator has a bore within a tubular body with a central axis andformed to receive drilling fluid. At least one fin is disposed withinthe bore, and a primary pathway and an alternate pathway are downstreamof the at least one fin. The alternate pathway is configured to directdrilling fluid towards a center of the tubular body. As the drillingfluid flows through the tubular body the at least one fin creates arotary motion within the drilling fluid forcing a denser portion of thefluid into the primary pathway which leads towards a center of thetubular body while a lighter portion of the fluid is routed into thealternate pathway which leads towards a periphery of the tubular body.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a cutaway view of an embodiment of a downhole drill stringsuspended from a drill rig.

FIG. 2 is a cutaway view of an embodiment of a drill bit connected to adownhole centrifugal drilling fluid separator.

FIG. 3 is a cross sectional view of an embodiment of a drill bitconnected to a downhole centrifugal drilling fluid separator.

FIG. 4 is a cutaway view of an embodiment of a plurality of finsattached to a central hub and a tubular body.

FIG. 5 is a cross sectional view of an embodiment of a drill bitconnected to a downhole centrifugal drilling fluid separator.

FIG. 6 is a cross sectional view of an embodiment of a downholecentrifugal drilling fluid separator.

FIG. 7 is a cross sectional view of an embodiment of a downholecentrifugal drilling fluid separator.

FIG. 8 is a cross sectional view of an embodiment of a downholecentrifugal drilling fluid separator.

FIG. 9 is a partial cross sectional view of an embodiment of a downholecentrifugal drilling fluid separator.

FIG. 10 is a cutaway view of an embodiment of a plurality of dynamicfins attached to a central hub.

FIG. 11 is a perspective view of another embodiment of a plurality ofdynamic fins attached to a central hub.

DETAILED DESCRIPTION OF THE INVENTION AND THE PREFERRED EMBODIMENT

Referring now to the figures, FIG. 1 displays a cutaway view of anembodiment of a downhole drill string 100 suspended from a drill rig101. A downhole assembly 102 may be located at some point along thedrill string 100 and a drill bit 104 may be located at the end of thedrill string 100. As the drill bit 104 rotates downhole, the drillstring 100 may advance farther into soft or hard earthen formations 105.The downhole assembly 102 and/or downhole components may comprise fluidseparation devices. Further, surface equipment may send data and/orpower to downhole tools and/or the downhole assembly 102.

FIG. 2 is a cutaway view of an embodiment of a drill bit 104 connectedto a downhole centrifugal drilling fluid separator 201. The centrifugaldrilling fluid separator 201 may comprise a plurality of exhaust ports203 formed in the wall 250 of the tubular component. The exhaust ports203 may direct a denser portion of drilling fluid with a higherconcentration of particulate matter 205 into the annulus of theborehole. At least one nozzle 207 may be disposed on the working face209 of the drill bit 104 and a lighter portion of drilling fluid with alower concentration of particulate matter 205 may exit these nozzles.

The lighter portion of drilling fluid may clear debris from the workingface 209 of the drill bit 104 before coalescing with the denser portionup the annulus. The combined lighter and denser portion may travel tothe surface of the borehole together.

The lighter portion of drilling fluid may cake the bottom of thewellbore with less particulate matter than it would have without theseparation, thereby, only minimally interfering with the cuttingelements 211 ability to cut fresh formation.

Also, since a significant amount of particulate matter is removed fromthe lighter portion, the lighter portion may exert a lower pressureagainst the wellbore's floor. Thus, in only selected regions of thewellbore, such as at the drill bit, a controlled under balance drillingsituation may be created. This may result in the formation's pressurecontributing to breaking the wellbore's floor, thus, enabling moreefficient drilling. Up the annulus, where the denser portion combineswith the lighter portion, the drilling fluid's weight may be moreappropriately matched to push against the wellbore's wall and preventcave-ins.

FIG. 3 is a cross sectional view of an embodiment of a drill bit 104connected to a downhole centrifugal drilling fluid separator 201. Thedownhole centrifugal drilling fluid separator 201 may comprise a borewithin a tubular body. The tubular body may comprise a first section 301and a second section 303. A plurality of fins 305 may be disposed withinthe bore of the first section 301 and the second section 303 maycomprise a plurality of exhaust ports 307. The second section may form athreaded connection 309 with the drill bit 104 (or other tool stringcomponent), thus, the drill bit 104 is in fluid communication with thesecond section 303. The underbalanced condition requires less effort topenetrate into the formation 105, thus, increasing the rate ofpenetration and durability of the drill bit 104.

The plurality of fins 305 may be rigidly attached to the inner diameterof the first section 305 and to a hub 311 disposed along the centralaxis of the tubular body. Drilling fluid pumped through the plurality offins 305 may comprise a predetermined concentration of particulatematter 205. The predetermined concentration may be chosen at the surfaceof the borehole and may be determined by many factors including thedepth of drilling and properties of the formation 105. Drilling fluidpumped through the plurality of fins 305 may create a rotary motionwithin the drilling fluid forcing particulate matter 205 away from thecentral axis, thus, forming a denser and lighter portion of drillingfluid. The denser portion of drilling fluid may be propelled furthertowards the inner diameter due to its heavier weight, while the lighterportion may remain closer to the center of the sections.

The drilling fluid may flow into the second section 303 of the tubularbody in their separated conditions. The second section 303 may have anincreased diameter leading to a plurality of exhaust ports 307 adjacentto a tapered ledge 313. Since inertia is acting on the denser drillingfluid, it may follow the increased diameter leading to the exhaustports. The lighter portion of drilling fluid may continue to flow intothe drill bit and out of the nozzles.

FIG. 4 is a cutaway view of an embodiment of a plurality of fins 305attached to a central hub 311 and to an inner diameter of the tubularbody. The fins are rigidly fixed to the hub, which is rigidly fixed tothe inner diameter of the bore wall. Thus, this hub and fins are notconfigured to rotate independent of the inner diameter. Instead, thishub and fins are designed to force the drilling fluid to change's itstrajectory. The fins 305 may be welded, bolted, or otherwise rigidlyfastened to the hub 311 and the tubular body. The plurality of fins 305may comprise a rounded leading edge 350 followed by a sharp trailingedge 351 to decrease drag. Each fin in a leading row 352 may be spacedaround the circumference of the central hub 311 and may havesubstantially the same angle of attack. The succeeding trailing rows353, 354 may progressively increase in angle and may be configured toenhance the centrifugal effect on the drilling mud. While only threerows are shown in the embodiment of FIG. 4, the scope of the inventionsincludes any number of rows and any range of increasingly steeperangles.

Fluid may be pumped through the plurality of fins 305. Each row of fins305 may affect the direction of the fluid flow without a single level offins 305 taking all the force and wear caused by the force of theflowing fluid. The amount of relative centrifugal force acting upon thefluid may be dependent on the flow rate of the fluid being pumped intothe downhole system. As the flow rate increases, so does the amount offorce available to separate out particulate matter.

FIG. 5 comprises a first section 501 that comprises a plurality of fins505 and a second section that comprises a plurality of exhaust ports 505adjacent to an annular fluid channel 507 formed in the tubular body. Thefluid channel 507 may be formed by a guide barrier 509 that extends intothe bore formed in the tubular body of the first section 501.

The channel may comprise a narrowing thickness as it approaches theexhaust ports 505. The exhaust ports 505 may comprise a cup shapedgeometry that may transfer the downward force of the drilling fluid intoan upward force inducing the lighter and denser portions of drillingfluid to coalesce above the exhaust ports 505. The fluid channel 507 andcup shaped geometry may further allow for less buildup of dense drillingfluid as it passes through the exhaust ports 505 preventing a buildup ofparticulate matter 205.

FIG. 6 is a cross sectional view of an embodiment of a downholecentrifugal drilling fluid separator 201 connected to a drill bit 104comprising a deployable center indenting element 601 or other centerresiding drilling components, such as turbines, motors, electronics,pumps, mud sirens, jars, and combinations thereof. The deployable centerindenting element 601 may be actuated by drilling fluid flowing into apiston chamber 603. A porting mechanism 605 may direct the drillingfluid into the piston chamber 603 such that the deployable centerindenting element 601 generates a hammering action while drilling. Thedrill bit 104 may further comprise at least one turbine 607 inconnection with the porting mechanism 605 to direct the drilling fluid.

Lighter drilling fluid may flow through the at least one turbine 607 andinto the porting mechanism 605 and the hammering action of the centerindenting element 601 may provide increased efficiency in the drillingprocess. The lighter drilling fluid may reduce the wear on both theporting mechanism 605 and at least one turbine 607 while reducing thebuildup of particulate matter in the piston chamber 603.

In some embodiments, the denser drilling fluid may be expelled out ofthe tool string above the bottom-hole assembly, preventing the drillingfluid's caking effect to plug up the downhole tool's equipment or weardown their components. The denser portion of drilling fluid may beexpelled out of the tool string above any component that may bepotentially harmed by dense drilling fluid.

FIG. 7 discloses a primary and alternate pathway 707, 702 disposeddownstream of the hub and fins 305. The lighter drilling fluid flowsinto the primary pathway, which routes the drilling mud out of thetubular body 703 and into the annulus 701 of the wellbore. Thus, thedrilling fluid that remains in the tubular body comprises an increasedconcentration of particulate matter and/or is a heavier weight. In someembodiments, downhole tools like mud driven motors may be operate betterwith a heavier drilling mud weight. In some embodiments, the lighterportion of the drilling fluid may comprise lost circulation materialand/or fibrous materials that are lighter than the heavier portion ofthe drilling fluid.

FIG. 8 discloses the primary and secondary pathways 707, 702 beingconcentric to one another. The alternate pathway may be annular, and thepathways are separated be a tubular structure 800. The primary pathwaycomprises a downhole tool 801, which may be configured to operateideally in a lighter weight drilling mud. In some embodiments, thedownhole tool may comprise ports and/or small apertures, which mayeasily cake off in a heavy weight drilling mud. The downhole tool mayalso be a mechanism that is configured to further separate out thedrilling weight densities. In the embodiment of FIG. 8, the heavierweight drilling mud may bypass the tool by traveling down the alternatepathway. The lighter and heavier weight drilling muds may recombine whenthe primary and alternate pathways converge downstream of the downholetool.

FIG. 9 discloses the primary pathway 707 routing the lighter portion ofthe drilling fluid to the periphery 900 of the tubular body, while thealternate pathway 702 directs the heavier weight drilling mud into thecenter of the tubular body. An upstream section 901 of the primarypathway may collect the lighter weight drilling fluid and curve to theperiphery as the pathway continues downstream. A curved section 902 ofthe primary pathway may cross a barrier 903 that forms the alternatepathway.

The heavier weight drilling mud may be routed from the periphery of thetubular body towards the center through a narrowing diameter 904 of thebarrier 903. A downhole tool configured to operate more efficiently maybe disposed within a central portion of the alternate pathway. In someembodiments, the alternate and primary pathway may converge anddownstream.

FIG. 10 is a cutaway view of an embodiment of a plurality of dynamicfins 1001 attached to a central hub 1003 in a tubular body. Theplurality of dynamic fins 1001 may comprise a first and second level1005, 1007 separated by a plurality of stators 1009. The first level1005 of dynamic fins may comprise a greater attack angle than the secondlevel 1007. The plurality of stators 1009 may be rigidly attached to thetubular body. As fluid flows through the tubular body, the first level1005 of fins direct the fluid into a circular motion while fins move inthe opposite direction. The second level of fins 1007 may spin in thesame direction as the fluid, thus, inducing a greater centrifugal force.

FIG. 11 is a perspective view of another embodiment of a plurality ofdynamic fins 1001 attached to a central hub 1003. The plurality ofdynamic fins 1001 may comprise a first and second level 1005, 1007. Thefirst and second level 1005, 1007 may be separated by a plurality ofstators 1009. The first level 1005 may be in mechanical connection withat least one outer gear 1101 and the at least one outer gear 1101 may bein mechanical connection with a central gear 1103. The central and outergears 1101, 1103 may comprise a gear ratio such that every turn of theouter gear 1101 may result in multiple turns of the central gear 1103.The central gear 1103 may be in mechanical connection with the secondlevel of dynamic fins 1007 so as the central gear 1103 completes arevolution, so will the second level of dynamic fins 1007.

1. A downhole drilling fluid separator, comprising: a bore within atubular body comprising a central axis and formed to receive drillingfluid; at least one fin disposed within the bore; at least one downholetool is disposed within a primary pathway downstream of the at least onefin; an alternate pathway is also downstream of the at least one fin andby passes the at least one tool; and the primary and alternate pathwaysconverge downstream of the at least one tool; wherein as drilling fluidflows through the tubular body the at least one fin creates a rotarymotion within the drilling fluid forcing a denser portion of the fluidinto the alternate pathway while a lighter portion of the fluid isrouted into the primary pathway.
 2. The separator of claim 1, whereinthe lighter portion comprises lost circulation material and/or fibrousmaterials.
 3. The separator of claim 1, wherein at least one additionalfin that causes a rotary motion within the drilling fluid is disposedwithin the primary pathway.
 4. The separator of claim 1, wherein thedownhole tool is a motor.
 5. The separator of claim 1, wherein thedownhole tool comprise electronic equipment.
 6. The separator of claim1, wherein the alternate pathway is annular.
 7. The separator of claim1, wherein the primary and alternate pathways are concentric to eachother.
 8. The separator of claim 1, wherein the at least one fin isrigidly fixed to the bore of the tubular body.
 9. The separator of claim1, wherein the primary pathway is substantially aligned with a centralaxis of the tubular body.
 10. The separator of claim 1, wherein thealternate pathway is substantially aligned with a central axis of thetubular body.
 11. The separator of claim 1, wherein the primary andalternate pathways are separated by a tubular structure.
 12. Theseparator of claim 1, wherein another mechanism for separating drillingfluid densities is disposed within the primary pathway.